Without limiting the scope of the present invention, its background will be described with reference to producing fluid from a hydrocarbon bearing subterranean formation, as an example. During development of a well traversing a hydrocarbon-bearing subterranean formation, various operations are typically performed and various equipment run-in and pulled from the wellbore. Treatment of a wellbore can include the injection of fluids into the formation, and in particular, the injection of steam or other heated fluid from a work string into the wellbore annulus.
Artificial lifting techniques are used where formations lack adequate pressure to cause hydrocarbons to rise to the surface. Pumps can be used in the wellbore or at the surface to bring fluids to the surface. Gas can be injected into the wellbore to lighten the weight of fluids and facilitate their movement towards the surface. In other instances, a compressible fluid, like pressurized steam, is injected into adjacent wellbores to urge hydrocarbons towards a producing wellbore. The steam, through heat and pressure, reduces the viscosity of the oil and urges it towards a production wellbore. Injection operations are known in the industry and not described in detail here. Selective injection along various intervals of the wellbore is often accomplished with selectively openable valves, such as sliding sleeve valves, and the like, and often in conjunction with isolation devices such as packers, plugs, bridge plugs and the like.
During injection operations, steam (water and vapor) can be lost prior to injection as it condenses into liquid (water). Most water loss occurs along the surfaces of the tubulars through which the steam is injected. Additional losses occur at ports and passageways, especially where the steam must change direction of flow at a sharp angle. Consequently, an operator may inadvertently inject an undesired ratio of water and vapor at a given interval. Further, the condensate water tends to collect near the far end of the injection string, resulting in a high vapor content injection uphole and a low vapor injection content downhole.
Attempts have been made to limit condensation, entrain condensate water back into the steam flow, and to manage water to vapor ratio. For example, it has been suggested that fluid flow be routed through various sizes and arrangements of ports, selectively openable valves, nozzles, throats and diffusers, or that the injection fluid flow be pulsed, oscillated, and modified from axial to rotational patterns. For further disclosure regarding steam injection, see the following references, each of which is incorporated herein by reference in their entirety for all purposes: U.S. Pat. No. 6,708,763 to Howard et al., U.S. Pat. No. 7,032,675 to Steele et al., U.S. Pat. No. 7,909,094 to Schultz et al., U.S. Pat. No. 6,158,510 to Bacon et al., U.S. Pat. No. 7,367,399 to Steele at al., and U.S. Pat. No. 5,607,018 to Schuh. Further, commercial tools are available from Halliburton Energy Services, Inc., such as the Zonemaster (trade name) Injection System.
However, condensation and its control remain a concern. Accordingly, a need exists for a downhole injection tool and method of use to reduce and control condensation.
It should be understood by those skilled in the art that the use of directional terms such as above, below, upper, lower, upward, downward and the like are used in relation to the illustrative embodiments as they are depicted in the Figures, the upward direction being toward the top of the corresponding Figure and the downward direction being toward the bottom of the corresponding Figure. Where this is not the case and a term is being used to indicate a required orientation, the Specification will state or make such clear.